Monthly State of the Market Report - SPP

Monthly State of the Market

Report

June 2010

published July 15, 2010

produced by SPP Market Monitoring Unit

Copyright © 2009 by Southwest Power Pool, Inc. All rights reserved.

SPP Market Monitoring Unit

Monthly State of the Market Report 2 June 2010

Table of Contents

Executive Summary ........................................................................................................................................ 3

Figures .............................................................................................................................................................. 4

Figure 1 – SPP EIS Price Contour Map ..............................................................................................4

Figure 2 – Congestion by Shadow Price Impact – June 2010 ............................................................5

Figure 3 – Congestion by Shadow Price Impact – Previous 12 months .............................................6

Figure 4 – Breached and Binding Flowgates by Interval ...................................................................7

Figure 5 – LIP / Gas Cost Comparison ...............................................................................................8

Figure 6 – Hourly Price Ranges by Market Participant – June 2010..................................................9

Figure 7 – Hourly Price Ranges by Market Participant – Previous 12 months ................................10

Figure 7a – Price Duration Curve – Previous 12 months .................................................................11

Figure 8 – Regional Monthly Prices .................................................................................................12

Figure 9 – Energy Generation by Fuel Type ....................................................................................13

Figure 10 – Wind Generation & Capacity ........................................................................................14

Figure 11 – Fuel on the Margin ........................................................................................................15

Figure 12 – EIS Settlements - GWh .................................................................................................16

Figure 13 – EIS Settlements - $ ........................................................................................................17

Figure 14 – Depth of Energy Market for Resources Only – by Status .............................................18

Figure 15 – Ramp per 100 MW of Online Capacity .........................................................................19

Figure 16 – Monthly Summary of Market Ramp Rate Deficiency ..................................................20

Figure 17 – Dispatchable Range .......................................................................................................21

Figure 18 – Transmission Owner Revenue .......................................................................................22

Figure 19 – Average Transmission Reservations and Schedules .....................................................23

Figure 20 – RNU Components .........................................................................................................24

DISCLAIMER The data and analysis in this report are provided for informational purposes only and shall not be considered or relied upon as market advice or market settlement data. The Southwest Power Pool Market Monitoring Unit (SPP MMU) makes no representation or warranties of any kind, express or implied, with respect to the accuracy or adequacy of the information contained herein. The SPP MMU shall have no liability to recipients of this information or third parties for the consequences arising from errors or discrepancies in this information, or for any claim, loss or damage of any kind or nature whatsoever arising out of or in connection with (i) the deficiency or inadequacy of this information for any purpose, whether or not known or disclosed to the authors, (ii) any error or discrepancy in this information, (iii) the use of this information, or (iv) a loss of business or other consequential loss or damage whether or not resulting from any of the foregoing.



Executive Summary

The average electricity price (LIP) in the SPP Energy Imbalance Service market for June

2010 was $33.05/MWh, an increase of 19% from May 2010. During the same period, gas

cost at the Panhandle hub increased by 16% ($3.91 to $4.52/MMBtu). The SPP LIP

continues to closely correlate changes in gas cost, as shown in the supplemental chart that has

been added at the bottom of Figure 5 showing LIP and gas cost since implementation of the

EIS market in February 2007.

In Figure 7a, a 12-month Price Duration curve has been added to the report. The price

duration curve charts the SPP load-weighted average LIP over the 12 months from high to

low. The graph shows that 97.4% of SPP load-weighted hourly LIP values occur inside a

range of 2 standard deviations from average. (Normally distributed, approximately 95% of

all data points should fall inside of this 2 standard deviation range.) This indicates that SPP

hourly LIPs are normally distributed with an appropriate number values outside of this range.

Overall congestion was down for June with decreases in both breached and binding intervals

(Figure 4) from last month as well as June in previous years. The impact of congestion on

LIP was also lower in June as evidenced by the highest average hourly shadow price in the

month of $24.63 (Figure 2), which is roughly one-third of the highest from both last month

and one year ago.

Areas seeing the most localized congestion during June (Figure 1 & 2) were:

1. NE Kansas

2. NW Missouri

3. SW Kansas

4. Shreveport area

Most of the congestion can be attributed to either planned or unplanned line outages, or

heavier flows due to typical summer-time demand.

Wind capacity factor remained high for June at 39%, compared to 29% last June. Since June

2009, wind capacity has increased by 16%, while wind generation increased by 53%.

During June 2010, the SPP EIS Market experienced the highest generation totals since the

start of the EIS market (Figure 9). An all-time high for peak load in the market footprint was

experienced on June 22. (This peak has not been adjusted to account for expansion of the

market footprint that occurs with the addition of new market participants.)



Figures

Figure 1 – SPP EIS Price Contour Map

June 2010

500 kV

345 kV

230 kV

161 kV

138 kV

115 kV

69 kV

Oklahoma City

Tulsa

12 Month EIS Price Contour Map

500 kV

345 kV

230 kV

161 kV

138 kV

115 kV

69 kV

Oklahoma City

Tulsa

NE Kansas

NW Missouri

Shreveport Area

SW Kansas



Figure 2 – Congestion by Shadow Price Impact – June 2010

0%

10%

20%

$0

$20

$40

%T

ota

l In

terv

als

Co

ng

este

d

Avera

ge H

ou

rly S

had

ow

Pri

ce

($/M

Wh

)

Average Hourly Shadow Price ($/MWh) % Total Intervals Congested

Region Flowgate Name Flowgate Location (kV) [Control Area]

Average Hourly

Shadow Price

($/MWh)

Total % Intervals

(Breached or Binding)

Detailed Description

NE Kansas KELSENEMACON Kelly – S. Seneca (115) ftlo

E. Manhattan – Concordia

West (230) [WR] $ 24.63 7.4%

The Mullergren – Spearville 230 kV line was out for

maintenance in early June causing the market to have

trouble solving the congestion on the flowgate.

NW Missouri

LAKALASTJHAW Lake Road – Alabama (161) ftlo St. Joe – Hawthorn

(345) [KCPL] $ 20.08 3.2%

Heavy North – South flow from Nebraska into Kansas with the addition of excess flow from MISO caused

congestion in the Kansas City load pocket.

TEMP10_16439 Platte City – KCI (161) ftlo

Stranger Creek – Craig

(345) [KC PL] $ 19.22 2.3%

Congestion due to heavy West - East flow into Kansas

City. Switching to lower the flow on TEMP10

increased flow on LAKALASTJHAW.

SW Kansas

TEMP09_16438 Holcomb – Plymell Switch

(115) ftlo Hitch – Potter South (345) [SECI]

$ 19.68 8.4% Temporary added to control overloading on 115 kV Holcomb – Plymell. Increaasing wind output and

imports adds to existing N-S flow in western Kansas. HOLPLYHOLSPE

Holcomb – Plymell Switch

(115) ftlo Holcomb -

Spearville (345) [SECI] $ 12.45 2.4%

Shreveport

Area

TEMP03_16364 S Shreveport – Wallace Lake (138) ftlo Dolet Xfmr

(345/230) [CSWS-CLEC] $ 11.54 2.3%

High N-S flow through the S. Shreveport load pocket.

SPP, AEP and CLECO established an operating guide on TEMP03 to help manage the situation.

TEMP17_16372 Longwood – Noram Tap (138) ftlo Harts Island – S

Shreveport (138) [CSWS] $ 9.30 1.6%

Other

TEMP08_16410

Chamber Springs –

Farmington (161) ftlo Tontitown – Dyess (345)

[CSWS]

$ 7.72 0.8% Due to the outage of Dyess – Elm Springs. Identified

possible work around, opening breakers at Chambers

Springs to relieve loading.

OSGCANBUSDEA Osage Switch - Canyon East (115) ftlo Bushland -

Deaf Smith (230) [SPS] $ 7.15 8.4%

Formerly known as TEMP01_15940. Congestion due to high N-S flow. Breaches generally occur in this area

with high fluctuating wind and/or area generation

outages along with limited transmission capability available.

REDWILLMINGO Red Willow – Mingo (345)

[NPPD – SECI] $ 6.59 7.4%

Unplanned three day outage on Gentleman – Red Willow 345 kV caused congestion on this transmission

line due to typical heavy North-South flow.



Figure 3 – Congestion by Shadow Price Impact – Previous 12 months

0%

10%

20%

30%

$0

$10

$20

$30

%T

ota

l In

terv

als

Co

ng

este

d

Avera

ge H

ou

rly S

had

ow

Pri

ce

($/M

Wh

)

Average Hourly Shadow Price ($/MWh) % Total Intervals Congested

Flowgate Name

Flowgate Location (kV)

Control Area

Average Hourly

Shadow Price

($/MWh)

Total % Intervals

(Breached or Binding)

Proposed Solution [estimated completion date]

RANPALAMASWI Randall County - Palo Duro

(115) ftlo Amarillo – Swisher (230)

SPS $ 20.48 9.8%

The new Canyon West to Spring Draw 115 kV line (regional

reliability upgrade) will add some capacity to the Amarillo area

and may provide a level of mitigation to this constraint.

[12/16/2012]

LAKALAIATSTR Lake Road – Alabama (161)

ftlo Iatan to Stranger Creek

(345)

MPS-

KCPL $ 17.89 3.7%

The new Iatan 345/161 kV substation and the Iatan tap of the

Platte City to Stranger Creek 161 kV line (generation

interconnection upgrades) will add some capacity to the Iatan

area and may provide a level of mitigation to this constraint.

[4/1/2010].

LONSARPITVAL Lone Oak to Sardis (138) ftlo Pittsburg – Valiant 345

CSWS $ 11.65 2.7%

The conversion of the McAlister to Canadian River 69 kV line

to 138 kV (regional reliability upgrade) will add some capacity

in eastern Oklahoma and may provide a level of mitigation to

this constraint. [TBD]

GENTLMREDWIL Gentleman to Redwillow (345) NPPD $ 6.35 4.5%

The new Axtell-Wolf-Spearville 345 kV lines (Balanced

Portfolio upgrades) will add capacity to the Gentleman area and

may mitigate this constraint of the north-south flow from

Nebraska to Kansas. [6/1/2013].

SHAXFRTUCOKU Shamrock XFR (115/69)ftlo Tuco – Oklaunion (345)

CSWS-

SPS $ 5.90 3.7%

The new Tuco Interchange – Stateline – Woodward 345 kV line

(Balanced Portfolio upgrade) will add some capacity to the

Texas High Plains area and may provide a level of mitigation to

this constraint. [5/19/2014]

ELPFARWICWDR El Paso – Farber (138) ftlo

Wichita – Woodring (345) WR $ 5.02 3.0%

The new Rose Hill – Sooner 345 kV line (regional reliability

upgrade) will add some capacity to the Wichita area and may

provide a level of mitigation to this constraint. [1/1/2013]

OKMHENOKMKEL Okmulgee - Henryetta (138)

ftlo Okmulgee to Kelco (138) CSWS $ 3.72 1.5%

The new Seminole to Muskogee 345kV line (Balanced Portfolio

upgrade) will add capacity to the Tulsa area and may provide a

level of mitigation to this constraint. [12/31/2013]

MANIPMDOLSWS Mansfield – Int. Paper (138)

ftlo Dolet Hills – Swisher (345) CSWS $ 3.22 0.7%

Congestion occurred on this flowgate during a two week period

in 2009. There is no planned upgrade expected to provide

significant mitigation.

HPPVALPITVAL Hugo -Valliant (138) ftlo

Pittsburg – Valiant (345)

WFEC-

CSWS $ 3.16 2.1%

The new 19 mile Hugo to Valliant 345 kV line with 138/345 kV

XF at Hugo PP (transmission service upgrades) will add some

capacity to the Hugo area and may provide a level of mitigation

to this constraint. [4/1/2012]

COOPER_S Cooper-St. Joe (345) ftlo

Cooper – Fairport (345) NPPD $ 2.99 1.0%

The proposed Nebraska City - Maryville - Sibley 345 kV line

(priority projects upgrade) would add some capacity in the

Cooper_S corridor and may provide a level of mitigation to this

constraint. [not yet approved]



Figure 4 – Breached and Binding Flowgates by Interval

0%

5%

10%

15%

% D

isp

atc

h I

nte

rvals

Bre

ach

ed

% Intervals Breached

0%

20%

40%

60%

80%

100%

% D

isp

atc

h I

nte

rvals

Bin

din

g

% Intervals Binding

intervals Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

last 12 months

% Breached

8.8% 8.2% 5.9% 4.5% 3.6% 3.2% 6.6% 3.4% 2.6% 6.8% 10.6% 7.5% 6.1% 5.8%

% Binding

83.9% 87.3% 82.7% 53.5% 52.6% 54.7% 59.4% 41.5% 48.8% 74.4% 82.5% 68.9% 55.3% 63.6%

Source: OBIEE/MOS



Figure 5 – LIP / Gas Cost Comparison

$20

$30

$40

$50

$60

$70

$80

$2

$4

$6

$8

$10

$12

$14

Ele

ctr

icit

y P

rice (

LIP

)

Gas C

ost

Gas (Panhandle) Electricity (LIP)

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May10

Jun 10

12 month

average

Electricity (LIP)

[$/MWh] 25.83 27.77 25.73 23.27 29.91 28.29 37.86 42.18 40.56 27.72 27.06 27.69 33.05 30.88

Gas Panhandle [$/MMBtu]

2.82 3.07 2.96 2.88 3.99 3.48 5.21 5.72 5.22 4.17 3.78 3.91 4.52 4.08

LIP/Gas Cost since Market Start

$20

$30

$40

$50

$60

$70

$80

$2

$4

$6

$8

$10

$12

$14

Ele

ctr

icit

y P

rice

Gas C

ost

Gas Electricity (LIP)



Figure 6 – Hourly Price Ranges by Market Participant – June 2010

33.05

-$100

$0

$100

$200

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

-$100

$0

$100

$200

Pri

ces (

$/M

Wh

)

Market Participant

MP Max MP Min MP Average SPP Average =

in $ AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

Max 264 115 115 115 115 115 776 133 154 136 115 115 115 226 115 115 115 190 791 115 115 115

Avg 34 33 26 33 32 33 38 33 35 34 33 26 26 35 33 33 27 38 38 26 33 33

Min -22 -27 -288 -5 -3 -12 -4 -2 -1 -1 -12 -309 -271 -26 -17 -12 -292 -10 -3 -287 -15 1



Figure 7 – Hourly Price Ranges by Market Participant – Previous 12 months

30.88

-$200

-$100

$0

$100

$200

$300

$400

$500

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KEPC KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

-$200

-$100

$0

$100

$200

$300

$400

$500

Pri

ces (

$/M

Wh

)

Market Participant

MP Max MP Min MP Average SPP Average =

in $ AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KEPC KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

Max 483 483 283 532 485 483 1,169 293 485 485 258 484 485 485 485 482 482 485 493 1,199 485 482 484

Avg 32 33 27 34 30 32 35 33 30 30 26 30 25 25 29 32 31 25 29 34 25 32 29

Min -117 -39 -360 -178 -175 -161 -471 -175 -174 -174 -30 -168 -498 -425 -238 -143 -127 -475 -198 -494 -422 -127 -171



Figure 7a – Price Duration Curve – Previous 12 months

-$500

-$400

-$300

-$200

-$100

$0

$100

$200

$300

$400

$500

0 1000 2000 3000 4000 5000 6000 7000 8000

LIP

($/M

Wh

)

Hours

Hourly LIP SPP Average LIP 95% Range

LIP ($/MWh)

95% Range Top $ 63.76

SPP 12 month Average $ 30.88

95% Range Bottom $ -2.00

% of Hourly LIP values inside 95% range

97.4%

The 95% range indicates 2 standard deviations for the mean (average) LIP for the 12

month period. Assuming a normal distribution, approximately 95% of hourly LIP values

should occur inside of this range. Having 97.4% of instances occur inside of this range

indicates that SPP Hourly LIPs are distributed as should be expected with an appropriate

number of hourly LIP values outside of this range.



Figure 8 – Regional Monthly Prices

$0

$10

$20

$30

$40

$50

Jun 09 Jul 09 Aug 09 Sep 09 Oct 09 Nov 09 Dec 09 Jan 10 Feb 10 Mar 10 Apr 10 May 10 Jun 10

$/M

Wh

SPP MISO ERCOT

Region Average

Price Maximum

Price Minimum

Price Volatility

Average On-Peak

Price

Average Off-Peak

Price

SPP $ 33.05 $ 141.57 $ -38.46 45% $ 39.43 $ 26.94

MISO $ 33.65 $ 219.61 $ -83.92 61% $ 42.43 $ 25.25

ERCOT $ 39.03 $ 316.28 $ 5.16 75% $ 44.13 $ 34.15

Note: This table is a “rough comparison” because of inherent differences in the structure of the three markets and also because of the differences in how prices for SPP, MISO, and ERCOT are calculated. For SPP, load weighted averages are used, while the data from MISO and ERCOT are not load weighted. Volatility is measured by the Coefficient of Variation, which is the standard deviation across all hours divided by the average of all hours.

0%

50%

100%

150%

200%

250%

Jun 09 Jul 09 Aug 09 Sep 09 Oct 09 Nov 09 Dec 09 Jan 10 Feb 10 Mar 10 Apr 10 May 10 Jun 10

Regional Price Volatility

SPP Volatility

MISO Volatility

ERCOT Volatility



Figure 9 – Energy Generation by Fuel Type

0

5,000

10,000

15,000

20,000

Jun 08

Jul 08

Aug 08

Sep 08

Oct 08

Nov 08

Dec 08

Jan 09

Feb 09

Mar 09

Apr 09

May 09

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Gen

era

tio

n (

GW

h)

Other Hydro Wind Nuclear Gas Coal

in GWh Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Coal 11,672 12,841 12,446 11,444 11,070 11,294 12,952 12,198 11,317 11,277 9,828 10,871 12,578

Gas 5,379 5,943 5,860 4,007 2,895 2,646 3,943 4,459 3,630 2,858 2,931 3,859 5,984

Nuclear 1,763 1,811 1,629 1,641 614 519 1,556 1,814 1,664 1,599 1,716 1,819 1,723

Wind 619 535 663 532 834 840 849 747 502 1,069 1,091 909 945

Hydro 201 154 131 167 190 180 95 147 166 169 160 185 223

Other 11 10 12 15 13 13 12 13 17 21 17 17 18

Total 19,645 21,294 20,741 17,806 15,616 15,492 19,407 19,378 17,296 16,993 15,743 17,661 21,470

by % Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

12 month

average

Coal 59% 60% 60% 64% 71% 73% 67% 63% 65% 66% 62% 62% 59% 64%

Gas 27% 28% 28% 23% 19% 17% 20% 23% 21% 17% 19% 22% 28% 22%

Nuclear 9% 9% 8% 9% 4% 3% 8% 9% 10% 9% 11% 10% 8% 8%

Wind 3% 3% 3% 3% 5% 5% 4% 4% 3% 6% 7% 5% 4% 4%

Hydro 1% 1% 1% 1% 1% 1% 0% 1% 1% 1% 1% 1% 1% 1%

Other 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Source: OBIEE/MOS



Figure 10 – Wind Generation & Capacity

0

500

1,000

1,500

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Win

d G

en

era

tio

n (

GW

h)

Win

d C

ap

acit

y (M

W)

Wind Capacity (MW) Wind Generation (GWh)

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Capacity (MW)

2,939 2,939 3,040 3,103 3,202 3,202 3,313 3,313 3,313 3,313 3,381 3,381 3,402

Generation (GWh)

619 535 663 532 834 840 849 747 502 1,069 1,091 909 945

Capacity Factor

29% 24% 29% 24% 35% 36% 34% 30% 23% 43% 45% 36% 39%

# of Resources

46 46 47 48 49 49 51 51 51 51 53 53 54

Source: OBIEE/MOS

Note: One 20MW wind resource was added in June 2010.



Figure 11 – Fuel on the Margin C

oal

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas G

as

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

0%

20%

40%

60%

80%

100%

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

last 12 months

Other 0.2% 0.0% 0.1% 0.1% 0.1% 0.0% 0.3% 0.1% 0.0% 0.2% 0.5% 0.9% 0.3% 0.2%

Coal 42.2% 34.7% 33.7% 45.8% 37.4% 39.5% 31.9% 29.9% 25.6% 41.9% 43.8% 46.6% 40.4% 37.6%

Gas 57.5% 65.3% 66.2% 54.1% 62.6% 60.5% 67.9% 70.0% 74.4% 57.8% 55.7% 52.5% 59.3% 62.2%

Source: OBIEE/MOS

Note:

During non-congested periods, one resource sets the price for the entire market. During congested

periods, the market is effectively segmented into several sub-areas, each with its own marginal

resource. Each congested interval counts the same as a non-congested period, but the marginal fuel

type for each sub-area is represented proportionally in the congested period.



Figure 12 – EIS Settlements - GWh

0%

5%

10%

15%

20%

0

10,000

20,000

30,000

40,000

EIS

Tra

nsacti

on

s a

s %

of

To

tal

GW

h

Scheduled Transactions (GWh) Load EI GWh Resource EI GWh % EIS Transactions

in GWh Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Resource EI 3,691 3,293 2,875 2,541 2,333 2,483 2,840 2,805 2,159 2,565 2,597 2,770 2,980

Load EI 1,491 1,056 630 526 476 546 642 623 532 551 550 582 669

Scheduled Transaction

33,451 37,608 37,726 31,407 28,392 27,970 35,158 35,469 31,864 30,644 27,817 31,477 38,975

Total Energy 38,633 41,956 41,232 34,474 31,201 31,000 38,641 38,896 34,555 33,760 30,964 34,829 42,625

by % Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Last 12 Months

Resource EI 9.6% 7.8% 7.0% 7.4% 7.5% 8.0% 7.3% 7.2% 6.2% 7.6% 8.4% 8.0% 7.0% 7.4%

Load EI 3.9% 2.5% 1.5% 1.5% 1.5% 1.8% 1.7% 1.6% 1.5% 1.6% 1.8% 1.7% 1.6% 1.7%

Scheduled Transactions

86.6% 89.6% 91.5% 91.1% 91.0% 90.2% 91.0% 91.2% 92.2% 90.8% 89.8% 90.4% 91.4% 90.9%

Totals may not equal 100% due to rounding.



Figure 13 – EIS Settlements - $

$0

$100

$200

$300

Mil

lio

ns

Resource EI Load EI

in million $ Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

12 Month Average

Resource EI 100 92 74 59 69 70 107 122 87 76 73 77 97 84

Load EI 41 31 17 13 15 16 26 28 23 17 17 17 23 20

Total EI 141 122 92 72 84 85 133 150 111 93 90 95 121 104



Figure 14 – Depth of Energy Market for Resources Only – by Status

-

5,000

10,000

15,000

20,000

GW

h P

rod

ucti

on

Other Manual (other) Manual (intermittent) Nuclear Self-Dispatch Market Dispatch

in GWh Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Market Dispatch

15,300 16,721 15,789 13,393 12,576 12,733 15,490 15,139 13,699 13,020 11,758 13,450 16,613

Self-Dispatch 719 984 1,636 1,173 741 534 470 407 336 399 326 328 749

Nuclear 1,764 1,817 1,633 1,639 614 514 1,561 1,832 1,675 1,614 1,734 1,821 1,723

Manual (intermittent)

697 615 705 587 894 922 898 833 573 1,175 1,181 1,027 1,058

Manual (other) 1,235 1,245 1,030 1,077 863 811 1,052 1,369 1,119 974 908 1,122 1,334

Other 2 (6) 0 (12) (11) (6) 4 (2) (7) (9) (4) (8) (6)

TOTAL 19,717 21,375 20,794 17,857 15,677 15,549 19,475 19,578 17,395 17,174 15,903 17,741 21,470

by % of total

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Last 12 Months

Market Dispatch 78% 78% 76% 75% 80% 82% 80% 77% 79% 76% 74% 76% 77% 77%

Self-Dispatch 4% 5% 8% 7% 5% 3% 2% 2% 2% 2% 2% 2% 3% 4%

Nuclear 9% 9% 8% 9% 4% 3% 8% 9% 10% 9% 11% 10% 8% 8%

Manual (intermittent) 4% 3% 3% 3% 6% 6% 5% 4% 3% 7% 7% 6% 5% 5%

Manual (other) 6% 6% 5% 6% 6% 5% 5% 7% 6% 6% 6% 6% 6% 6%

Other 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Note: May not total to 100% due to rounding. Source: MOS



Figure 15 – Ramp per 100 MW of Online Capacity Offered and Available to the EIS Market

-

10

20

30

40

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

Avera

ge O

nli

ne C

ap

acit

y (

GW

) p

er

Inte

rval

MW

/ M

inu

te /

100 M

W o

f O

nli

ne C

ap

acit

y

Available Online Capacity MW / Min Offered / 100 MW of Online Capacity

Jun 09

Jul 09

Aug09

Sep09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

12 month average

MW / Minute / 100 MW of

Online Capacity

0.87 0.87 0.87 0.77 0.84 0.83 0.80 0.81 0.79 0.79 0.79 0.80 0.88 0.82

Average Online Capacity (GW)

per Interval 34,882 36,002 35,620 31,463 26,316 27,201 31,867 32,478 31,575 28,608 27,571 30,767 37,573 31,420



Figure 16 – Monthly Summary of Market Ramp Rate Deficiency

-

40

80

120

160

200

240

280

320

360

-

20

40

60

80

MW

Ram

p A

vail

ab

le p

er

Min

ute

Ram

p D

efi

cie

ncy I

nte

rvals

UP Ramp Deficiency Intervals DOWN Ramp Deficiency Intervals Total MW Ramp Available per Minute

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

12 month average

UP Ramp Deficiency Intervals

10 3 7 12 37 43 35 25 22 11 2 16 6 18

DOWN Ramp Deficiency Intervals

32 0 5 4 0 5 0 0 0 3 16 35 14 7

Total Ramp Deficiency Intervals

42 3 12 16 37 48 35 25 22 14 18 51 20 25

% of Total Market

Dispatch Intervals

0.5% 0.0% 0.1% 0.2% 0.4% 0.6% 0.4% 0.3% 0.3% 0.2% 0.2% 0.6% 0.2% 0.3%

MW Ramp Available per

Minute 303 313 305 242 221 224 256 263 249 227 219 254 331 259



Figure 17 – Dispatchable Range

32%

36%

40%

44%

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

last 12 mo

Average 37.8% 37.7% 37.5% 36.4% 37.7% 39.2% 37.8% 36.9% 36.2% 36.2% 35.4% 37.4% 34.7% 36.9%

Dispatchable Range is calculated as the average dispatachable range available (in MW) divided by

the average of the daily peak demand (MW) for the month.



Figure 18 – Transmission Owner Revenue

$0

$10

$20

$30

$40

$50

$60

Mil

lio

ns

in millions $ JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

2008 32.1 34.6 33.1 33.0 32.9 32.1 32.6 33.8 37.7 34.7 35.0 36.3

2009 35.7 34.2 33.4 43.8 41.0 43.1 43.4 43.7 42.7 41.3 40.0 43.5

2010 44.7 43.9 46.6 54.3 52.0 52.3



Figure 19 – Average Transmission Reservations and Schedules

0%

10%

20%

30%

40%

50%

60%

0

100

200

300

400

500

600

Jun 08

Jul 08

Aug 08

Sep 08

Oct 08

Nov 08

Dec 08

Jan 09

Feb 09

Mar 09

Apr 09

May 09

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Th

ou

san

ds M

Wh

Avg. Daily Transmission Reservations Schedules as a % of Reservations

in thousands MWh

Jun 09

Jul 09

Aug09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

12 month average

Average Daily

Reservations 448 420 412 399 390 382 445 485 496 482 469 476 536 449

Average Daily

Schedules 100 101 102 91 87 74 110 113 119 93 96 101 117 100

% 21% 24% 25% 23% 22% 19% 25% 23% 24% 19% 21% 21% 22% 22%



Figure 20 – RNU Components

-$6

-$4

-$2

$0

$2

$4

Mil

lio

ns

SP LOSS UDC U/S O/S EIS Total RNU

$ (thousands) Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

EIS 1,816 1,336 760 1,051 2,737 -245 -923 -1,166 1,347 589 2,617 1,564 -750

O/S -1,183 -164 -89 -71 -95 -99 -101 -45 -26 -96 -113 -92 -101

U/S -540 -259 -51 -41 -31 -177 -257 -91 -52 -78 -112 -141 -71

UDC -135 -134 -84 -64 -71 -56 -136 -138 -81 -35 -48 -62 -98

SP Loss -21 -28 1 -7 -8 -2 -17 -5 -6 -3 -27 -4 1

Total RNU -63 752 538 869 2,531 -579 -1,434 -1,444 1,181 377 2,319 1,265 -1,018

EIS (Energy Imbalance Charge/Credit) – All energy deviations between actual generation or load and schedules are settled as (EIS).

O/S (Over-Scheduling Charge) - During any hour, if Locational Imbalance Prices diverge and a Market Participant’s Load imbalance is more than 4% (but at least 2 MW) at an applicable Settlement Location in that hour, that MP may be subject to an Over-Scheduling Charge.

U/S (Under-Scheduling Charge) - During any hour, if Locational Imbalance Prices diverge and a Market Participant’s Load imbalance is more than 4% (but at least 2 MW) at an applicable Settlement Location in that hour, that MP may be subject to an Under-Scheduling Charge.

UDC (Uninstructed Resource Deviation) – the difference between the dispatch instructions and the actual performance of a Resource.

SP Loss - Self-Provided Losses

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Monthly State of the Market Report - SPP

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